Stimulated fracturing operations are intended to increase the productivity of a hydrocarbon reservoir working well. These operations consist of injecting a high-pressure fluid into a layer of the subsoil where the reservoir is located. The injection of the fluid produces microfractures in the layer. This technique makes it possible to increase the permeability of the reservoir by favoring hydrocarbon circulation via the microfractures to the well.
However, these operations require continuous monitoring of the reservoir so as, on one hand, to monitor the progress of the fracturing operation and, on the other, stop the operations when the fracturing is sufficient.
Known monitoring techniques make use of the fact that the microfractures generated in the layer induce micro-earthquakes which are propagated and can be detected by seismic receivers.
International Patent Publication No. WO 2008/033797 describes a monitoring method wherein the seismic receivers are arranged on the soil surface. The subsoil zone to be monitored in divided into a plurality of cells. An expected travel time between each cell and each receiver is then calculated using a subsoil velocity model. The seismic signals received by the receivers and recorded by the recorder (referred to as “traces”) are corrected to account for the differences in expected travel times between one cell and each of the receivers, and the sum calculated. The summed data (referred to as “source” data) are analyzed to detect the presence of a possible (or “triggering”) event characterized by a large amplitude and high energy parameters. The monitoring method described in WO 2008/033797 does not enable rapid data processing, and is not suitable for real-time subsoil monitoring.
U.S. Pat. No. 7,391,675 describes a real-time monitoring wherein the seismic receivers are arranged in a well, which may be either the producing well or another well. The method consists of migrating the seismic data recorded to perform continuous mapping of the subsoil, on the basis of a predictive travel time model of the waves P and S in the subsoil, and detecting a time of a location corresponding to a maximum coalescences associated with the occurrence of an event. One drawback of the method of U.S. Pat. No. 7,391,675 is that it is necessary to install receivers inside a well, which complicates the installation and increases the cost. In addition, if the receivers are installed in the injection well, the well tends to vibrate under the effect of this injection, which raises the noise level on the receivers positioned in this well. It is not always possible to have access to another well.
Furthermore, the following documents describe the use of a perforation shot to calibrate a velocity model: 1) SPE 115722, Denver, 21-24 Sep. 2008, “Velocity Calibration for Microseismic Monitoring: Applying Smooth Models With and Without Perforation Timing Measurements”, Pei et al., and 2) EAGE Workshop on Passive Seismic, Limasol, 22-25 Mar. 2009, A-13, “Dual Treatment Monitoring with Horizontal Receiver Array”, Michaud et al.